Nuclear Magnetic Resonance (NMR) tools used for well-logging or downhole fluid characterization measure the response of nuclear spins in formation fluids to applied magnetic fields. Downhole NMR tools typically have a permanent magnet that produces a static magnetic field at a desired test location (e.g., where the fluid is located). The static magnetic field produces a magnetization in the fluid. The magnetization is aligned along the direction of the static field. The magnitude of the induced magnetization is proportional to the magnitude of the static field. A transmitter antenna produces a time-dependent radio frequency magnetic field that has a component perpendicular to the direction of the static field. The NMR resonance condition is satisfied when the radio frequency is equal to the Larmor frequency, which is proportional to the magnitude of the static magnetic field. The radio frequency magnetic field produces a torque on the magnetization vector that causes it to rotate about the axis of the applied radio frequency field. The rotation results in the magnetization vector developing a component perpendicular to the direction of the static magnetic field. This causes the magnetization vector to precess around the static field at the Larmor frequency. At resonance between the Larmor and transmitter frequencies, the magnetization is tipped to the transverse plane (i.e., a plane normal to static magnetic field vector). A series of radio frequency pulses are applied to generate spin echoes that are measured with the antenna.
NMR measurements can be used to estimate, among other things, formation porosity. For example, the area under the curve of a T2 distribution for a NMR measurement can be equated to or at least provides an estimate of the NMR-based porosity. The T2 distribution may also resemble the pore size distribution in water-saturated rocks. The raw reported porosity is provided by the ratio of the initial amplitude of the raw decay and the tool response in a water tank. This porosity is independent of the lithology of the rock matrix.
Another tool used to estimate formation porosity, among other things, is a dielectric permittivity tool (also known as a dielectric constant tool). A dielectric permittivity tool measures the dielectric permittivity of a material. The dielectric permittivity is related to the ability of electric dipoles in a material to form and align themselves with an alternating electric field. Water molecules have large dipole moments and consequently the dielectric permittivity of water is high. It is precisely this high dielectric permittivity, particularly as compared to oil, gas, and typical rock matrices encountered in hydrocarbon exploration, that dielectric measurements often seek to exploit. Dielectric permittivity tools generally operate at high frequencies (e.g., gigahertz), at least as compared to conventional electromagnetic resistivity tools.
Estimation of adsorbed gas volume in Coal Seam Gas (CSG) or Coal Bed Methane (CBM) in a timely manner remains a challenge for operators. The most common current technique is to collect core samples from a borehole. The freshly cut cores are sealed in airtight desorption canisters and the volume of gas that desorbs over time is measured. The measured desorbed gas volume generally underestimates the correct gas volume due to lost gas, i.e., the gas that desorbs before the cores can be placed in the airtight desorption canisters. Correction for lost gas may be estimated, but this method yields widely different in-situ gas volume estimates depending upon the coal sample type, collection methodology, analysis conditions, and data analysis methods. The method may also take up to six months to yield results, the long period being required for better measurement accuracy.